US8515880B2 - Condition monitoring of an underwater facility - Google Patents

Condition monitoring of an underwater facility Download PDF

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US8515880B2
US8515880B2 US12/887,088 US88708810A US8515880B2 US 8515880 B2 US8515880 B2 US 8515880B2 US 88708810 A US88708810 A US 88708810A US 8515880 B2 US8515880 B2 US 8515880B2
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monitoring
condition
facility
parameter
valve
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US20110071966A1 (en
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Stuart Holley
Nicholas Ellson
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Baker Hughes Energy Technology UK Ltd
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Vetco Gray Controls Ltd
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    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B44/00—Automatic control systems specially adapted for drilling operations, i.e. self-operating systems which function to carry out or modify a drilling operation without intervention of a human operator, e.g. computer-controlled drilling systems; Systems specially adapted for monitoring a plurality of drilling variables or conditions
    • G—PHYSICS
    • G05—CONTROLLING; REGULATING
    • G05B—CONTROL OR REGULATING SYSTEMS IN GENERAL; FUNCTIONAL ELEMENTS OF SUCH SYSTEMS; MONITORING OR TESTING ARRANGEMENTS FOR SUCH SYSTEMS OR ELEMENTS
    • G05B23/00—Testing or monitoring of control systems or parts thereof
    • G05B23/02—Electric testing or monitoring
    • G05B23/0205—Electric testing or monitoring by means of a monitoring system capable of detecting and responding to faults
    • G05B23/0218—Electric testing or monitoring by means of a monitoring system capable of detecting and responding to faults characterised by the fault detection method dealing with either existing or incipient faults
    • G05B23/0243—Electric testing or monitoring by means of a monitoring system capable of detecting and responding to faults characterised by the fault detection method dealing with either existing or incipient faults model based detection method, e.g. first-principles knowledge model
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00—Survey of boreholes or wells
    • E21B47/001—Survey of boreholes or wells for underwater installation
    • G—PHYSICS
    • G05—CONTROLLING; REGULATING
    • G05B—CONTROL OR REGULATING SYSTEMS IN GENERAL; FUNCTIONAL ELEMENTS OF SUCH SYSTEMS; MONITORING OR TESTING ARRANGEMENTS FOR SUCH SYSTEMS OR ELEMENTS
    • G05B23/00—Testing or monitoring of control systems or parts thereof
    • G05B23/02—Electric testing or monitoring

Definitions

  • This invention relates to a method for monitoring the condition of apparatus located at an underwater facility and condition monitoring means for monitoring a component of an underwater facility.
  • the invention is applicable to an underwater facility such as a subsea hydrocarbon production facility.
  • Subsea equipment associated with the production of oil and gas is generally designed with a design life of up to about thirty years.
  • faults and failures still regularly occur within these complex pieces of equipment. Intervention operations to recover failed modules may be extremely costly and the availability of vessels to perform these operations at short notice may be limited. Also, failures within the equipment can be potentially harmful to both the environment and personnel safety.
  • Types of subsea equipment failure include for example:
  • a current approach towards detecting such failures is to utilise sensors fitted to subsea equipment to measure various parameters within the electrical/electronic, hydraulic, chemical and production systems. There may be many such sensors deployed subsea. Many of these measurements are monitored via a control system located topside, i.e. at the surface either on land or on a vessel or platform.
  • parameter monitoring uses statically defined alarm set-points to alert an operator, local to the control system, that an abnormal condition, indicating a fault or failure, is present.
  • the monitoring system may be set to raise an alarm once a pressure sensor measures a pressure higher than a set, predetermined value.
  • This method has various associated problems. These include:
  • the invention enables the remote monitoring of the condition of subsea equipment to provided enhanced feedback and abnormal condition detection.
  • the invention through modelling of the measured parameters, provides early warning and diagnostic information, to enable preventative actions to be undertaken or maintenance to be scheduled.
  • the invention may be used with existing subsea installations, using the sensors already present, or alternatively, new installations could be optimised for enabling the invention.
  • a sensor associated with the component for sensing a parameter and outputting a signal indicative of said parameter
  • an expert system arranged to receive each said output signal, the expert system including a model of expected behaviour of said parameter.
  • FIG. 1 schematically shows an overview of an exemplary monitoring system in accordance with the present invention
  • FIG. 3 schematically shows a typical well control hydraulic system.
  • FIG. 1 schematically shows an overview of an exemplary monitoring system in accordance with the present invention.
  • This system is implemented as an expert system, located remotely from the topside's control system, which interprets data autonomously and provides feedback to an operator on the health of the monitored facility and also provides advice on potential maintenance requirements.
  • FIG. 1 divides the system into four locations: subsea, topside, remote location and remote user.
  • a subsea apparatus component 1 for example, but not limited to, a well tree (or “Christmas tree”), manifold, power generation or storage device, communications or power distribution hub, electronics or control module is located at the seabed.
  • This apparatus component 1 has sensors 2 associated with it.
  • sensors 2 typically a large number of sensors are provided, so that various parameters may be measured. These may include for example pressure, temperature, flowrate of hydraulic or production fluids, electrical current, component temperature etc, although any sensor output could be incorporated into a system in accordance with the present invention.
  • a subsea electronics module SEM 3
  • SEM subsea electronics module
  • SCM subsea control module
  • control station 6 Located topside, i.e. at the surface, for example on land or on a vessel or platform, are a control station 6 and topside equipment 7 linked thereto.
  • the control station 6 is in communication with subsea via an umbilical cable 5 , such that the processed sensor data may be transmitted from the subsea electronics module 3 to the topside control station 6 via the umbilical 5 .
  • the topside control station 6 comprises means for converting the sensor data into a format optimised for transmission, typically using the established TCP/IP protocol, using an interne or satellite link to a remote location.
  • remote location means a location remote from the subsea equipment. In many cases this location will also be remote from the topside location, for example at a central control base, but may optionally be located at the topside location.
  • a remote monitoring application 8 Situated at the remote location is a remote monitoring application 8 .
  • This comprising processing means adapted to perform much of the data analysis required by the present invention to determine the health of the subsea apparatus 1 .
  • the remote monitoring application 8 is linked to a historical database 9 , which stores historical data and expected behaviour models for processes and components of the subsea apparatus 1 . This enables the remote monitoring application 8 to function as a so-called expert system, as will be described in more detail later.
  • a remote terminal 10 is provided to enable an end user to view the system status remotely.
  • the terminal 10 may be in communication with the remote monitoring application 8 via a secure web-based interface for example.
  • a system status notification component 11 is provided, so that the end user may be autonomously notified of abnormal system behaviour both through the remote interface and through the use of email notifications.
  • the notification system can also act as a means of sharing data with third party equipment vendors who may be required to diagnose the state of their equipment.
  • remote users may send information to the remote monitoring application 8 .
  • the system may receive feedback and improve its analysis through learning, as mentioned below.
  • the expert system preferably comprises both analytical computer models and input from an external source, for example experienced personnel, which may both stored in the historical database 9 .
  • an external source for example experienced personnel, which may both stored in the historical database 9 .
  • the system is capable of incorporating feedback and learning from experiences, to enhance the model(s) and the improve the system's operation.
  • the system collates all of the many individual parameter data from the sensors 2 , measuring the data either continuously, or at discrete points in time. Each data condition is assigned a priority rating, which affects the weighting of each data condition in the overall assessment.
  • the prioritisation takes the form of a ranked number system assigned to alarms of certain groupings (see example below), in descending order of importance in terms of its effect on the equipment:
  • Any alarms associated with the parameter data are also collated by the system. These alarms may constitute hard limits, or trending or conditional limits and have the same rating philosophy as applied to the other data above.
  • the system can then summarise the status of the equipment within the monitored well facility, to provide an overall health score and a simplified view of the subsea system status.
  • a typical subsea control system utilises a composite subsea umbilical 5 to transmit from the topside control station 6 , electrical power and communication signals subsea, alongside hydraulic and chemical supplies.
  • the subsea end of umbilical 5 terminates in an umbilical termination assembly (UTA) 16 (see FIG. 3 ).
  • UTA umbilical termination assembly
  • the operation of the electrical distribution system is key to the operability of the subsea system.
  • Typical subsea electrical distribution systems operate at between 150 to 600 volts, but with longer offset distances these voltages increase into the kilovolts range. Breakdowns in the resistance of a conductor's insulation can cause a system failure and potentially harm to operators, or divers, working on the system. Also, conductors within the umbilical or flying leads and the electrical connectors have a tendency to break down over time.
  • LIM line insulation monitor device
  • the present invention enables the utilisation of the existing telemetry that current condition monitoring systems already provide from sensors, both at the surface power supply and within the subsea equipment. Relevant parameters include insulation resistance, voltage and current monitoring. These measured parameters are fed into a model to determine the expected behaviour and interaction of the variables, using both historical data and a physical model. The output may thus predict and flag abnormal degradation of the system behaviour to provide early warning of likely faults.
  • the health of the umbilical electrical conductors may be assessed using the following parameters measured over a period of time:
  • FIG. 2 shows a graph which illustrates the technique and demonstrates its advantage of early detection of a problem relative to the existing reliance on an alarm limit.
  • Hydraulic fluid is used to operate various valves subsea.
  • the fluid is pressurised at the surface (shore or platform/vessel) then transported through an umbilical 5 to the subsea control module 4 .
  • the subsea control module 4 distributes this fluid using electrically actuated directional control valves (DCVs) 19 (see FIG. 3 ).
  • DCVs electrically actuated directional control valves
  • Pressure transducers e.g. 18 , 21 , see FIG. 3
  • flow meters e.g. 17 , see FIG. 3
  • the control system is generally set to a fail-safe position, so in the event that hydraulic pressure is lost, the well will be shut down.
  • a method in accordance with the present invention may automatically detects leaks based on some or all of:
  • FIG. 3 illustrates diagrammatically a simplified well control hydraulic system, which for clarity shows only one well tree and no associated distribution manifolds.
  • Hydraulic fluid in a reservoir 12 feeds a hydraulic power unit (pump) 13 with the pump's output flow measured by a flow meter 14 . All these components are mounted typically on a well control platform topside (i.e. at the surface).
  • the output from the flow meter 14 feeds a well head tree via an umbilical 5 , the umbilical's input hydraulic pressure being measured by a pressure transducer 15 .
  • the umbilical 5 connects, via an umbilical termination assembly 16 , to a subsea control module 4 .
  • DCVs directional control valves
  • the flow meters shown in FIG. 3 may not always be present. If they are not present, then the flow rate or volume could be calculated using e.g. pressure drops, pump revolutions or by any other means available.
  • Fault determination could be assessed either statically or dynamically.
  • the static approach may be more applicable for the analysis of the control system, as generally such fluid is used only occasionally.
  • the dynamic approach may be more appropriate as the flows are relatively constant.
  • Fluid volumes or flow rates may be calculated from:
  • Output from a flow meter may be converted into a volume as would be used for the static approach by integration over time, while conversely volume outputs, for example as would be measured directly from the change of level of surface of the reservoir, may be converted into a flow rate for use with the dynamic approach by measuring with respect to time.
  • V 6 An expected amount of fluid used (V 6 ) is derived from the known volume required to move an actuator 21 through its full stroke—or partial stroke in the case where the position is measured or calculated separately.
  • the presence and location of a leak for the simple single well tree configuration shown in FIG. 3 can be determined using logic such as that set out below:
  • V 4(n) represents the equivalent value V 4 for tree “n”
  • V 5(n) represents the equivalent value V 5 for tree “n”:
  • Pressure gauges can also be used to determine if there are any leaks without the operation of valves. For example:
  • the same logic can be applied to any fluid system, for example chemical injection or produced fluid.
  • a choke valve is used to control the flow from a producing well or control the rate of injection of fluid into an injection well (or chemicals into a flow line). Production fluid flow is measured using physical flow-meters capable of measuring multi-phase flow.
  • the present invention enables the choke position to be determined, and compared to a measured position, from the flow rate through the choke.
  • a physical flow meter may be used to measure the flow directly.
  • the flow may alternatively be determined by using the pressure and temperature measurements at the inlet and outlet of the choke, and the choke's known flow rate and pressure drop characteristics.
  • Typical problems that can arise with chokes include erosion and inaccuracy of position setting. Choke valves by their nature erode, resulting in a reduced functionality. Operators setting a choke to achieve a specific restriction and thus pressure flow characteristic may see a different characteristic because of this erosion.
  • the position of the choke flow controlling sleeve can be monitored using a linear potentiometer (LVDT), other direct measurement device or, for a stepper-type choke, by counting the number of pulses sent to the stepper drive, whilst other methods may be used for rotary actuators. All of these methods are subject to inaccuracies (e.g. drift on a sensor, failure to count ‘steps’, etc) which can result in a different position being achieved to the one desired by the operator.
  • LVDT linear potentiometer
  • the physical flow meter gives a flow rate and volume fraction of component fluids such as gas, water or oil etc. Using this flow rate and pressure sensors on each side of the choke, it is possible to calculate the restriction of the choke, by comparing determined flow rates with expected flow rates for various choke positions. Any difference between the two may be due to erosion (if the actual restriction is less than desired restriction), plugging, or false position indication.
  • a false position indication can be isolated from erosion/plugging by moving the choke to an extreme position, either open or closed. However, this may not be desirable or possible.
  • An alternative method is to move the choke around the position at which it has been held for an extended period. Due to the nature of chokes only the part ‘open’ to flow will erode and by moving the plunger around this position a characteristic deflection will be apparent—isolating erosion from a false position indication.
  • the open part of the choke i.e. that exposed to flow, may erode or plug, leading to a difference between the expected throughflow and the actual throughflow. Now, for all choke positions which are more open (e.g.
  • the difference ⁇ between expected and actual flow will be substantially constant with x, since erosion/plugging cannot affect the closed part of the choke (since it is not exposed to the flow).
  • the difference ⁇ will vary as a function of x.
  • FIG. 3 shows a typical hydraulic circuit including a number of directional control valves (DCVs) 19 . These are valves, operated by electrical solenoids, which control hydraulic fluid flow to a vale actuator 20 .
  • a subsea control module 4 mounted on the tree, houses the or each DCV 19 .
  • the module 4 also contains pressure sensors 18 and 21 , that measure the pressure of driving fluid on the supply and driven sides respectively of the or each DCV (only one sensor 21 is shown in FIG. 3 for simplicity, it will be understood by those skilled in the art that each DCV 19 may have such an associated sensor 21 on its driven side). From these measurements the volume of fluid consumed by an actuation of the DCV may be calculated, since the pressure/flow characteristics of the DCV 19 are known.
  • volume can also be measured directly on the supply side by a flow meter 17 if present, which, as shown, may also be located in the module 4 .
  • a flow meter 17 if present, which, as shown, may also be located in the module 4 .
  • VFVP valve footprint verification program
  • Subsea actuators can fail which can lead to the inability to operate a valve, which in turn can cause significant control and safety issues.
  • the failures can be gradual in nature, such as deterioration of a seal, repeated sticking and becoming free before finally becoming permanently stuck, which in turn requires a gradual increase in pressure required to activate.
  • a method in accordance with the present invention may:
  • the time taken to fully stroke an actuator is a function of the hydraulic fluid supply pressure, accumulator volume, hydrostatic pressure, spring constant of the actuator and frictional losses, such as fluid restrictions or actuator/valve friction. All of these are either known before installation or measured during use, except the frictional losses. Therefore, a relationship between the stroke time and other measurements can be determined for each actuator. Any deviations from this relationship therefore signifies a change in the frictional losses, and thus impending failure. This could be due to fluid blockage or mechanical friction changes (seal failure, mechanical interference, etc.). Likewise, the same method can be used to monitor the time taken for the actuator to stroke closed, usually forced by a spring within the actuator.
  • the volume of hydraulic fluid necessary to move the actuator is monitored and trended.
  • a change in the volume of fluid used indicates an impending failure.
  • An increase in the fluid volume necessary indicates leaks (potentially of the seals) and a decrease in the fluid volume indicates an incomplete stroke or build up of debris.
  • the volume of fluid expelled when de-activating the valve may be recorded and trended in the same way. A decrease in the volume expelled indicates either that the actuator was not fully activated, is not fully de-activated, or that there is a leak before the flow meter. These causes may be differentiated by comparing the expelled fluid volume with the volume of fluid necessary for activation.
  • each valve will have a general ‘signature’ pressure/flow profile. This can be obtained during installation, testing or at any point before failure. Deviation from this signature during following operations can be monitored and trended to alert the operator to potential impending failures.
  • the above signature profiling method can be applied to a surface-controlled subsea safety valve (not shown).
  • This is an important safety valve, operated typically by a high pressure hydraulic fluid supply. It is used as a safety barrier, during well tests and work-overs.
  • the control electronics for a subsea well are typically located in a subsea electronics module (SEM) 3 (shown in FIG. 1 but omitted from FIG. 3 for clarity) which is typically located within an SCM 4 .
  • SEM 3 is critical to the control system. Current safety methods involve simply waiting for a failure, switching to back-up, and replacing when possible—hoping the backup does not fail. There is currently no active monitoring for failure prediction.
  • the electrical operation of the well is also dependent on subsea connectors which are complex wet-mate items and are often the point at which the electrical, hydraulic or chemical distribution fails. Problems with the connectors can often be solved by re-making them, which is relatively simple, but requires the mobilisation of a remote-operated vehicle.
  • An exemplary method in accordance with the present invention may:
  • Another exemplary method may include monitoring the condition of apparatus located at an underwater facility, comprising the steps of:
  • step c) comprises comparing the number of actuations to known life spans of actuator components.
  • the method further comprising the step of determining the time taken to fully stroke the actuator.
  • the method further comprising the step of using the determined time taken to calculate friction within the actuator.
  • the method can be used for detection and/or monitoring of failure of electronics components for controlling apparatus at the facility.
  • step a) includes sensing at least one of: temperature, pressure, humidity, current drawn by a component, signal levels and voltage at least one location in the facility.
  • the method further comprising the step of determining the health of an underwater electrical connector.
  • the health of the connector can be determined by obtaining at least one of: LIM measurements, hydraulic fluid flow determinations and chemical injection flow determinations.
  • a condition monitoring means for monitoring a component of an underwater facility comprising: a sensor associated with the component for sensing a parameter and outputting a signal indicative of said parameter; an expert system arranged to receive each said output signal, the expert system including a model of expected behaviour of said parameter.
  • the expert system can include a historical database.
  • the component can include an umbilical and an associated umbilical termination assembly, and the condition monitoring means can be adapted to monitor the condition of electrical conductors of the component.
  • the condition monitoring means further comprising sensors for sensing one or more of: a surface LIM reading, a surface input voltage, a surface input current, an underwater input voltage, an underwater input current and an underwater LIM.
  • the condition monitoring means further comprising means for collating any alarms associated with the parameter.
  • the component can include a hydraulic fluid system, and the condition monitoring means is adapted to detect and/or monitor hydraulic fluid leakage from the system.
  • the condition monitoring means further comprising sensors for sensing at least one of: activation of a valve at the facility, a flow of hydraulic fluid within the facility, an amount of hydraulic fluid leaving a hydraulic reservoir located at the surface and a hydraulic fluid pressure at one or more points within a control system of the facility.
  • the component can include a choke valve, and the condition monitoring means is adapted to detect and/or monitor wear or erosion within the choke valve.
  • the condition monitoring means further comprising means for determining a flow rate through the choke valve.
  • the flow rate determining means can have a flow meter in the proximity of the choke valve to directly determine flow therethrough.
  • the flow rate determining means can be sensors for measuring pressure and temperature characteristics of fluid at the inlet and outlet of the choke.
  • the component can have a valve actuator and the condition monitoring means is adapted to detect and/or monitor wear within valve actuator.
  • the condition monitoring means can further have means for determining the volume of fluid consumed by an actuation of the valve.
  • the volume determining means may be a hydraulic fluid pressure sensor located at each side of the valve.
  • the volume determining means can be a volume sensor.
  • the condition monitoring means may further comprise means for monitoring the number of actuations performed.
  • the expert system can be adapted to compare the number of actuations to known life spans of actuator components.
  • the condition monitoring means can also comprise means for determining the time taken to fully stroke the actuator.
  • the condition monitoring means may further comprise means for calculating friction within the actuator using the determined time.
  • the component can have electronics components for controlling apparatus at the facility, and the condition monitoring means is adapted to detect and/or monitor failure of the electronics components.
  • Means for sensing at least one of: temperature, pressure, humidity, current drawn by a component, signal levels and voltage at least one location in the facility may be included.
  • Means for determining the health of an underwater electrical connector can also be included.
  • the means for determining the health of the connector can have sensors for obtaining at least one of: LIM measurements, hydraulic fluid flow determinations and chemical injection flow determinations.

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BRPI1010460A8 (pt) 2016-04-12
AU2010224331A1 (en) 2011-04-07
EP2302479A3 (en) 2012-04-18
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MY177364A (en) 2020-09-14
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SG188850A1 (en) 2013-04-30

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